Comparing the parameters in Table 1 [14W. Tian, and H. Wang, "Latest understandings of the CBM development from high-rank coals in the Qinshui basin", Natural Gas Industry, vol. 35, pp. 117-123, 2015.], we can see that the average permeability of Qinshui basin is lower than other CBM basins, which resulted in the lower production. The geologic condition governs the producing ability of CBM reservoirs, and cannot be changed manly. What we can do is to make full use of the characteristics on the limited basis.

Table 1
The comparison of CBM characteristics in different countries.

Coal is anisotropic and dual porosity water saturated reservoir mainly containing methane. Most of the methane molecules in coal seam are present in adsorbed state as a layer of gaseous molecules on the coal surface, and only a minor amount is available in a free state. Methane is produced by reduction in overall pressure of the reservoir, which is achieved by dewatering,and desorbed methane flows through the cleat system into wellbore (Fig. 1).

Fig. (1) Methane desorption process [15R.G. Jeffery, W. Vlahovic, R.P. Doyle, and J.H. Wood, "Propped fracture geometry of three hydraulic fractures in sydney basin coal seams", In: SPE 50061, Presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia, 1988.].

Gas production from CBM reservoirs is governed by complex interaction of single-phase gas diffusion through micro-pore system and two-phase gas and water flow through cleat/fracture system that is coupled through diffusion process [15R.G. Jeffery, W. Vlahovic, R.P. Doyle, and J.H. Wood, "Propped fracture geometry of three hydraulic fractures in sydney basin coal seams", In: SPE 50061, Presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia, 1988.]. The whole production period includes 4 key points: dewatering to lower pressure, desorption, diffusion and flowing in fractures (Fig. 2).

Fig. (2) Methane gas producing period [15R.G. Jeffery, W. Vlahovic, R.P. Doyle, and J.H. Wood, "Propped fracture geometry of three hydraulic fractures in sydney basin coal seams", In: SPE 50061, Presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia, 1988.].

The gas producing rate depends on the slowest one among the 4 key processes. Because most methane is adsorbed on coal surfaces, and formation water exists in natural cleats, so, the methane is difficult to desorb freely, which results in the speed of desorption and diffusion of methane in coal matrix is the lowest. At this condition, the process of desorption and diffusion will determine the CBM production rate.

From above analysis, how to increase the speed of methane desorption and diffusion becomes the key to raise CBM production of single well. There are two ways to increase production, one is to raise the flowing rate, which actually is the lowest speed among desorption, diffusion, and flowing in natural fractures, and the other is to increase flowing drainage volume.

In coal seam, the vast majority of the gas is stored in coal matrix, which practically has no permeability. The flow to production well, however, occurs through the coal’s natural fracture system, which stores relatively small amount of gas. In order to achieve commercially viable gas production rate, interventions are necessary to be taken in CBM reservoirs. Hydraulic fracturing technique is therefor used in CBM, but it is a double-edged sword. On one hand, the conventional hydraulic fracturing can increase the gas flowing speed by creating man-made fractures. On the other hand, it cannot increase desorption and diffusion speed, which is the key factor to raise production, and it will also damage the coal matrix permeability.

For CBM reservoirs, the elastic modulus is lower (compared with sand), and Poisson’s ratio is larger, which result in coal rock be fractured easily. The fractures formed in CBM are wider and shorter, and the stimulation result is not as good as in sand reservoirs. During the process of fracturing treatment, especially when a large amount of sand is pumped into fractures, the reservoir around the fractures will be stressed severely, and the coal permeability is too sensitive to stress, so the coal permeability will be reduced extremely.

Based on the theory of linear elastic mechanics, the fracture width is proportional to net pressure in the fracture.

(1)

The coal permeability is sensitive to stress, and the relationship concluded by a lot of experiments is as follows [16D.P. Sparks, T.H. Mclendon, J.L. Saulsberry, and S.W. Lambert, "The effects of stress on coalbed reservoir performance, black warrior basin, U.S.A", In: SPE Annual Technical Conference & Exhibition,, Dallas, Texas, 1995.
[http://dx.doi.org/10.2118/30734-MS] ].

(2)

According to Table 2 [17Q. Zhu, Y. Zuo, and Y. Yang, "How to solve the technical problems in the CBM development: a case study of a CBM gas reservoir in the Southern Qinshui basin", Natural Gas Industry, vol. 35, pp. 106-109, 2015.], assume Young’s modulus of coal is 5000 MPa, Poisson’s ratio is 0.25, fracture height is 25 m, the initial permeability is 0.46 × 10^-3μm², the pore compressibility coefficient 0.16 MPa^-1. The fracture net pressure and permeability can be calculated by equation (1), (2) with different fracture width.

From Fig. (3), if net pressure increases from 1.0MPa to 5.5MPa, the fracture width will increase from 2.0 mm to 20 mm. In Fig. (4), when the fracture width increases from 2.0 mm to 20 mm, the matrix permeability will decrease from 0.45 × 10^-3μm² to 0.05 × 10^-3 μm², thus the damage around fracture is very severe. Since the coal rock is soft and the elastic modulus is low, the fracture width is normally more than 20 mm generated in fracturing treatment. The damage will be more severe, especially when more sands are pumped to prop the fractures fully. Because the permeability damage is difficult to recover during gas producing period, so it is the main reason that stimulation effect is not ideal in CBM.

Table 2
The mechanic parameters of rocks.

Fig. (3) Effect of different fracture width on net pressure.

Fig. (4) Effect of different fracture width on coal permeability around fracture.

The coal matrix permeability is low, but the natural fractures, such as butt and face cleats, are plenty in CBM reservoirs. How to make use of these natural fractures is an important issue. The conventional fracturing technique just considers how to open fractures, but do not focus on how to shear existing natural fractures and connect them with each other. For CBM reservoirs, the natural fractures should be treated properly. The micro-seismic monitoring results have shown that sheared and complex fractures are generated during fracturing treatments in CBM reservoirs [18C. Cipolla, X. Weng, M. Mack, U. Ganguly, H. Gu, and O. Kresse, "Integrating microseismic mapping and complex fracture modeling to characterize fracture complexity", In: SPE Hydraulic Fracturing Technology Conference and Exhibition, Woodlands, USA, January 24-26, 2011.
[http://dx.doi.org/10.2118/140185-MS] -21G. Naldrett, I. Oguche, S. Mazumder, D. Kubenk, and M. Scott, "The application of advanced wellbore monitoring in coal seam gas for continuous inflow profiling", In: SPE 171545 Presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 2014.
[http://dx.doi.org/10.2118/171545-MS] ]. Therefore, the mechanical condition for shearing fractures will be analyzed to provide foundation for network fracturing in CBM.

During the treatment of hydraulic fracturing, the vertical fracture always propagates perpendicular to the minimum horizontal in situ stress. The direction of natural fractures is in an angle with the maximum horizontal stress (Fig. 5). When hydraulic fracture is near to natural fracture, the pressure of hydraulic fracture is higher, in the meaning while, the permeability of natural fracture is larger than the coal matrix’s, so the fracturing fluid will enter into the natural fracture firstly, and lead to pressure increasing continuously. The natural fractures are close under initial reservoir condition, when more and more fracturing fluid flow into them, the pressure will raise rapidly, which results in the shearing of natural fractures before opening.

Fig. (5) Relationship between natural and main fractures [22S. Brooke-Barnett, S.K. Naidu, P.K. Paul, and T. Flottman, "Influence of in situ stress on fracture stimulation in the surat basin, southeast queensland", In: SPE 167064 Presented at the SPE Unconventional Resources Conference and Exhibition-Asia Pacific, Brisbane, Australia, 2013.].

The shearing force acted on the natural fracture can be calculated as follows [22S. Brooke-Barnett, S.K. Naidu, P.K. Paul, and T. Flottman, "Influence of in situ stress on fracture stimulation in the surat basin, southeast queensland", In: SPE 167064 Presented at the SPE Unconventional Resources Conference and Exhibition-Asia Pacific, Brisbane, Australia, 2013.].

(3)

The above equation can be transformed as follows.

(4)

When the angle between natural and hydraulic fracture is determined, the force to shear natural fracture can be satisfied under known fracture net pressure.

(5)

Hence, the fracture net pressure should satisfy the equation as follows.

(6)

When friction factor is 0.6, and fracture net pressure is 0.7 MPa, the critical stress difference can be calculated under different angles. If treatment net pressure surpasses this value, the natural fracture will shear and slide. The angle between natural and hydraulic fracture impacts the critical net pressure greatly (Fig. 6). When the angle is larger than 60^o, the critical net pressure will increase quickly. Under this condition, although the treating pressure raises much, it is difficult to shear the natural fracture. The direction of natural fractures is important for shearing, and it requires that the angle between natural and hydraulic fracture should be clarified before designing a proper treatment schedule.

The natural fractures will be opened if the fracturing net pressure is higher than the critical pressure and fracture closure pressure. In order to shear the natural fractures to generate fracture network, the fracturing net pressure should be controlled lower than the critical pressure during hydraulic fracturing treatment. After the network extends to a certain scope, the treatment pressure can be increased above the critical pressure to form a long main fracture, which connects the natural face and butt cleats to generate networks. Ideally, the fracture networks will stimulate the CBM reservoir fully and provide flowing drainage volume as large as possible [23B.R. Meyer, and L.W. Bazan, "A discrete fracture network model for hydraulically induced fractures: theory, parametric and case studies", In: SPE 140514 presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition, Woodlands, USA. January 24-26, 2011., 2011.
[http://dx.doi.org/10.2118/140514-MS] -30T. Flottman, S. Brooke-Barnett, R. Trubshaw, and S.K. Naidu, "Influence of in situ stresses on fracture stimulations in the surat basin southeast queensland", In: SPE Unconventional Resources Conference and Exhibition-Asia Pacific, Brisbane, Australia, November 11 – 13, 2013.
[http://dx.doi.org/10.2118/167064-MS] ]. Under lower net pressure, the damage around fractures can be avoided, and fracture networks can increase drainage volume obviously, thus, the methane producing rate will be raised greatly [31M.Y. Soliman, L.E. East, and J.R. Augustine, "Fracturing design aimed at enhancing fracture complexity", In: SPE Europe/EAGE Annual Conference and Exhibition, Barcelona, Spain, June 14-17, 2010.
[http://dx.doi.org/10.2118/130043-MS] -35T. Urbanic, and A. Baig, "Enhancing recovery in shales through stimulation of pre-existing fracture networks", In: SPE Hydraulic Fracturing Technology Conference, Houston, Texas, February 4-6, 2014.].

Fig. (6) Effect of angles between natural and main fractures on critical stress difference.

Assume that there are not proppants in sheared fractures, so the permeability can be calculated as follows.

(7)

If the width of sheared fracture is 10^-4 m, porosity is 1%, the permeability of sheared fracture will be 8.33μm². The permeability of coal matrix is usually at the level of 10^-3μm², obviously, the permeability of sheared fracture is far higher than the coal permeability, even the fracture width is in the scale of millimeter. When the sheared fracture is packed or sparsely by proppants, the width will be much larger, so the permeability will raise much. Therefore, the sheared fractures are important, and if they connect with each other to form fracture network, the production of CBM wells will rise significantly.